Murphy Oil Corporation
Q3 2013 Earnings Call Transcript

Published: 31 Oct 2013

[Operator:]

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation Third Quarter 2013 Earnings Conference Call. Today's conference is being recorded. At this time I'd like to turn the conference over to Mr. Roger Jenkins, President and Chief Executive Officer. Please go ahead, sir.

[Roger W. Jenkins:]

Thank you, operator, and good afternoon, everyone, and thank you for joining us on our call today. With me, as usual is Kevin Fitzgerald, Executive Vice President and Chief Financial Officer; John Eckart, our Senior Vice President and Controller; Barry Jeffery, Vice President, Investor Relations. And I'll turn it over to Barry for his customary comments.

[Barry F.R. Jeffery:]

Thanks, Roger. Today's call will follow our usual format. Kevin will begin by providing a review of third quarter 2013 results. Roger will then follow with an operational update, after which questions will be taken. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2012 Annual Report on Form 10-K filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I'll now turn the call over to Kevin.

[Kevin G. Fitzgerald:]

Thanks, Barry. Our net income for the third quarter of 2013 was $284.8 million or $1.51 per diluted share compared to net income of third quarter of 2012, $226.7 million or $1.16 per diluted share. For the 9 months of 2013, we had net income of $1.05 billion or $5.51% per diluted share and this compares to net income for the first 9 months of 2012 of $812.2 million or $4.17 per diluted share. This year's third quarter included income from discontinued operations of $32.7 million or $0.17 per diluted share compared to income of $15 million or $0.08 per diluted share for the same period last year. For the 9-month period 2013 included income from discontinued operations of $363.1 million or $1.91 per diluted share compared to income of $93.9 million or $0.48 per diluted share in 2012. The increase in the 2013 income for discontinued operations included gains on the sales of all E&P properties in the U.K. plus earnings through August from the U.S. downstream operations, which of course was spun off to shareholders at that time. So looking at income from continuing ops. In the third quarter of 2013, the income of $252.1 million or $1.34 per diluted share compared to income of third quarter 2012 of $211.7 million or $1.08 per diluted share. From continuing operations, for the first 9 months of 2013, net income of $684.9 million or $3.60 per diluted share compared to net income for the first 9 months of 2012 of $718.3 million or $3.69 per diluted share. Improved results from continuing operations in the third quarter of 2013 as compared to 2012 is mostly attributable to higher crude oil production levels. Looking at income by segment. In the E&P segment from continuing operations for the third quarter of 2013, net income of $264.2 million, that's compared to income from continuing ops from the E&P segment of $221.1 million in the third quarter of last year. Higher E&P earnings for the 2013 quarter were primarily attributable to higher oil sales volumes, particularly in the Eagle Ford Shale area of South Texas, partially offset by higher exploration expenses and higher DD&A and production expenses associated with the higher sales volumes. Crude oil and gas liquids production for the current quarter was approximately 138,100 barrels per day compared to approximately 105,800 barrels per day in the corresponding 2012 quarter, again with the increase mostly attributable to higher production at Eagle Ford. Natural gas sales volumes averaged 415 million cubic feet per day in the third quarter of this year compared to 454 million cubic feet per day in the third quarter of 2012. The decrease was attributable to lower volume at the Tupper area in British Columbia, as normal well decline occurred following voluntary deferral of development activities due to depressed natural gas prices; and in the Kikeh field offshore Malaysia, which was due to maintenance at the third-party onshore receiving facility. Now U.K. downstream, in the third quarter of 2013, we had a net charge of $12.9 million compared to net income of $25.5 million in the third quarter of last year. The decrease in the 2013 quarter was mostly attributable to significantly weaker results at the Milford Haven refinery. And the corporate segments, in the third quarter 2013, had net income of $800,000 compared to a net charge in the third quarter of last year of $34.9 million. This favorable variance is primarily related to after-tax gains from foreign currency transactions compared to losses in those transactions in the prior year. As of September 30, 2013, Murphy's long-term debt amounted to just under $2.6 billion or approximately 22.5% of total capital employed. This figure includes approximately $339 million associated with the capital lease of production equipment for the Kakap field offshore Malaysia. Excluding this lease, long-term debt to total capital employed at June 30 would be approximately -- at September 30, would be approximately 20.1%. And with that, I'll turn it over to Roger.

[Roger W. Jenkins:]

Thanks, Kevin. As Kevin pointed out in his remarks, on August 30, Murphy Oil Corp. completed the spin of Murphy USA as a single stand-alone entity. Murphy USA will report their financial results for the third quarter separately on November 6. The financial results of the U.S. downstream business for the first 2 months of the third quarter to Murphy Oil Corp. had been reported as discontinued ops in this third quarter release. The sales process for our U.K. downstream business continues. We're actively progressing the divestiture of those assets. Milford Haven refinery continues with safe, reliable operations in a difficult market. The U.K. marketing business continues to contribute solid results for the quarter and delivered one of its best months on record in September. Looking at the upstream market, we continue with strong oil pricing for our quarter 3 with our Malaysia oil netbacks averaging just over $91 per barrel for Kikeh and near $100 per barrel for SK oil, post all supplemental payments. Our SK gas averaged approximately $6.70 per MCF, and Eagle Ford Shale oil sold at $105 per barrel for the quarter. In offshore Gulf of Mexico, we had a Brent-supported price of near $107, as well as continued firm prices in the East Coast of Canada, which sold at near $114 per barrel. Our Seal crude had a strong netback price of $68 per barrel and Montney gas was priced in $281 per MCF, both including impacts of hedges in place. In the United States, NGL volumes were approximately 4,000 barrels per day at an average price in the mid-28 level, which is included in our reported realized U.S. crude prices and volumes. In exploration, in our global offshore exploration program, we're continuing to maintain focus in 4 areas

[Operator:]

[Operator Instructions] And we'll first go to Leo Mariani from RBC Capital Markets.

[Leo P. Mariani:]

Could you give us a little bit more color in terms of getting from the 207,000 barrels a day of production to the 199,000 in the fourth quarter? I know you talked about Kikeh oil shut-ins and Terra Nova, kind of some work-over activity there. Could you maybe kind of quantify the magnitude of some of those different pieces here, as we try to bridge the gap between Q3 and Q4?

[Roger W. Jenkins:]

Yes. As you go -- you want to go from 207,000 to 199,000, right?

[Leo P. Mariani:]

Yes.

[Roger W. Jenkins:]

Okay. Kikeh oil will be down around 10,000 a day. Terra Nova, 3,600. It produced just a little bit in quarter 3, and is down for mooring repair change. Tupper area has declined 3,400 BOE a day. SK Gas is down 1,500 a day. That's usually -- we forecast in based on downtime of that facility there. And those are some of the major ones. And we have some positive, with Syncrude having a better situation to the prior quarter and also the new SK Oil coming on. Those are the 2 uplifts at around 4,000 each, and the rest are sort of counterbalancing each other out. Leo, is that good enough for you?

[Leo P. Mariani:]

No, that's great. And I guess, additionally, you guys talked about sales volumes of 1 91, so obviously lower than sales. Maybe you can just kind of help us kind of get to that as well?

[Roger W. Jenkins:]

Yes, the major underlift there is in Malaysia, Leo. Basically, that's what all it is, their timing of lifting.

[Kevin G. Fitzgerald:]

We have a couple right at the end of the year. But we don't have them in, Leo, because it's literally on the date.

[Leo P. Mariani:]

Okay. No, that's helpful. Looking at your U.S. operating cost this quarter, they've been dropping pretty hard the past couple of quarters. I think you guys -- I had calculated just somewhere kind of just on LOE, maybe it's close to $10 a barrel. Maybe just kind of give us some more color. That is all Eagle Ford that's bringing op cost down that you guys said Eagle Ford was $13 a barrel, down $2 a barrel from the past quarter. Where do you guys think that can go in the long term on the op cost there?

[Roger W. Jenkins:]

In long term, I mean, Karnes, our oldest field, is in the 10 level now. And I think that would probably be the bottom. We may can get it into the 12 range across all the fields, but a real good job by our team there. Also in the Gulf, we're still putting all our U.S. together, Leo. And probably next year, we'll change that. But we have some barrels coming across Front Runner from off-leased production. That pulls some OpEx down there almost to 0. But it's a real Eagle Ford player because Eagle Ford's much more production than the Gulf, as we stand. But a great job there. But I don't see us going below 10 to 12 long term there.

[Leo P. Mariani:]

Got you, definitely helpful. Just looking at Seal. You guys did talk about the production sort of kind of hitting lower into the fourth quarter. You kind of talked about some of these pilot projects, your polymer, as well as your steam flood. Are you guys doing any kind of regular way, conventional drilling, is that activity all shelved? And how you kind of think about that as we go into next year?

[Roger W. Jenkins:]

It's pretty much shelved. I mean, you're looking at Seal next year being pretty close to the levels that it is now. We're just really focusing in on, I'd say, almost exactly where we are now. In production for next year -- I was just looking at it up. We're really trying to get our EOR lined up for steam, which I think is the big growth. If you look at our long-range plans, we really have -- don't have significant growth there to like 17, 18. And these are long-term projects to be approved by regulatory, and we've got a team in place looking to do to improve that. But we're real happy about the well we just have. But we want to just work on EOR and really get out of the conventional game. Because on a capital allocation business in North America, and that's run by one gentleman, it's difficult to compete with Eagle Ford, of course, there. But long term, lots of barrels, lots of steam ahead for us there, lot of steam success around us. But we haven't been a steam player. We're building up what we need to become one, and I'm happy with that transition.

[Leo P. Mariani:]

Okay, that's helpful. And I guess, just looking at your G&A. If my numbers are right, you guys were somewhere around $62 million in the third quarter from your non-E&P, I guess, your downstream segment. I guess, that number seemed kind of high. Can you give us any color there, maybe there were some transaction costs or something? And where should I go to sort of next quarter and beyond?

[Kevin G. Fitzgerald:]

Yes. We had a onetime transition costs with the separation of the sale of the business in the U.S. So we had upwards, over $15 million, probably $16 million, $17 million of onetime costs related to that in the third quarter. And more than that, when you look at it on a year-to-date basis.

[Leo P. Mariani:]

Okay, that's helpful for sure. In the Eagle Ford, you guys commented that you brought fewer wells online in the fourth quarter, and kind of talked about flattish production -- sorry, fewer wells online in the third quarter, then flattish production in the fourth quarter, sort of due to weather. I guess, should we anticipate that accelerating as we get into '14, where you'll start to get back on track and start bringing a lot more wells on? And can you maybe just throw some numbers around how many wells you brought on in the third quarter and what you expect in 4Q?

[Roger W. Jenkins:]

Yes, it's kind of my fault there. I've cut the capital machine back, trying to maintain some capital efficiency there. You can spend as much money as you want to in the Eagle Ford, I did not want to change our balance sheet to continue. We put on 90 -- 42 wells in the first quarter, 42 wells in the second. I'm giving you operated wells. We have 5 to 7 non-op, non-limited. It's an operated game business for us. And then when we went to 6 well pads and we cut back the CapEx down to 2, to have our spend maintained for the year. We dropped back to about 35 to 36 wells in the third quarter. We now are getting away from the 6 well pads. That didn't work so well for us. There's a water and sand requirements we needed. We've had trouble with our equipment, frac-ing that many wells in a row. And it just didn't work well across our acreage. We're going back to 4 well pads now and we're going to be delivering 42 wells, with an upside of 48 wells in the fourth quarter and getting back into probably front-loading our CapEx again, as we did last year. I think we grew production in that play about 24,000 barrels equivalent, last year with 182 wells. And we're looking at growing at about 17,000 with 160. So we're probably going to be 162-operated well player and probably get into 90 or 100 in the first half of the year every year will be typical how we play that, Leo.

[Operator:]

We'll now go to Evan Calio from Morgan Stanley.

[Evan Calio:]

First question on Siakap North. I think I understood your color on the project. But could you -- I mean, do you expect all that tie-back work to be completed in the fourth quarter before the monsoon season? Or is there -- will the project be completed now in 2 phases, one in November and then one in late 1Q? I think that was per the EPIC contractor's the recent update. What's the...

[Roger W. Jenkins:]

Yes, and we have some real disconnect between you and me on that. We have contractual agreement for them to do this work. We've recently signed a contractual agreement with that party. They're out there doing the work today. We broke the work up into several vessels, and all of that stuff are rattled off. It's a lot of significant work. This work is not difficult to do. You're down to it. The issue is weather risk. We have a contractual agreement around weather risk with that party that I'm happy with. You're talking to a guy that lived there for 6 years and knows all about monsoon weather in Malaysia, and built a bunch of stuff there. We're probably one of the more successful developers in that region. And we have a contract with a guy to do it. The guy's doing the work. We have one significant step left to go. If you ask me about my guidance, our plan on this well -- these wells flowing on December 15, I'd be very disappointed with my staff if they don't. But I don't have any barrels in the fourth quarter for it, we do not have, do not have, with McDermott, a split campaign to do this work. We have one campaign and the company loaded the pipe, and they come in to do the work and they're on the water to do the work today.

[Evan Calio:]

Okay, that's good news for you. On -- I shift gears onto exploration. I'm just curious what you learned from Eboni-1 well in Cameroon and how different the NTEM prospect is? And if that is -- is that the Ocean Confidence rig that comes back to drill that prospect in 2014?

[Roger W. Jenkins:]

First on DO matter. We're using Ocean Rover now. The Confidence is still off with another party there. We're kind of working off some of our commitment with DO with the Rover. The Rover went off to shipyard and coming back. Yes, disappointing, that well, Elombo, dry hole naturally, and we're still not concerned about that related to this. They're 2 totally separate projects. On the positive side, we established sand presence there that we tied to seismic, a very nice sand now, a very large structure we're drilling in NTEM. We did take a kick on this well on Elombo and had some heavy gas in our mud log there, which derisked petroleum system in the region. The Elombo well was a stratigraphic trap feature up against the fault. And that fault had leak, seal risk, and obviously leaked off. The feature that we're drilling in NTEM does not have that effect. It is a stratigraphic feature not down by that same fault. It's not connected up to Elombo, the main feature we're drilling. So learned something, I would say, about 2 years ago, if we'd had the data from Elombo, it would have lowered the risk a little bit on NTEM, but it's still rank frontier well. But it does not disappoint me to have to drill that well today.

[Evan Calio:]

Okay, that's good. And then lastly, if I could. The new acreage that you mentioned in your opening comments in Australia. Can you talk at all about what would you think there in terms of prospectivity? Is that...

[Roger W. Jenkins:]

Well there's been some announcements of other parties. You can look that up. There's been a lot of leasing and a lot of award of late. BP and Statoil, they're in the region, with 4 blocks and Chevron recently had the other 2 and we were able to come up with 1. This is rank frontier exploration. There was 1 dry hole drilled in this entire mass region. I mean, this block, we have is almost as big as Mississippi Canyon or half as big as Mississippi Canyon at least, enormous area, biggest in the entire gulf probably. One well drilled in, it was dry hole. And one of the blocks, another party lease. Very nice sand there. There was dredging done to the east -- I mean to the west of that block. That was some source -- oil sourcing material dredged down in the basin. This is announced prior to all the leasing. Our team worked this out. We have a presence there for a long time in Australia, and we were in a competitive bid environment with some others who came out with the block. And for a company like us, it's old-fashioned Murphy rank frontier exploration. We're proud of it and the advantage we have is there'll be a lot of drilling around us by other parties, while we're in our seismic phase. So it's very positive for our exploration group.

[Operator:]

And we'll now go to Blake Fernandez from Howard Weil.

[Blake Fernandez:]

Roger, you'll have to forgive me. I'm going to you straight to your probably least favorite topic here. But on the U.K., I was wondering if you guys could maybe provide a split on the $12.9 million loss between the refinery and the retail? And I guess, where I'm going with that is assuming the refining is really what's weighing on the result, is there an opportunity maybe if the sales process continues to drag on to maybe split off the retail and see if that could be marketed as a stand-alone?

[Roger W. Jenkins:]

This thing, Blake, I don't mind you asking about it at all, and you should ask. When you're trying to sell something like that for a long time, first thing, you've got to operate wells, so you can keep it running to try to sell it. And our team over there is doing a very good job of doing that. And very, very bad netbacks in refining. You're right, the refining is a big part of that. We haven't split that out before and while I'm in the middle of trying to sell something, probably not going to split it out today. And as long as we're in a data room and we're putting work in the data room and people are progressing and talking and working toward LOIs and trying to get to buy the thing, we're going to keep going forward with the process until that dries up. And that hasn't dried up, and we're working on it. And really I'm interested in selling it, but I'm not interested in just walking away from it at this point. We do have the opportunity to split it like you say. But today, as long as I have interested parties and do not have to split them into 2, I'm going to stay with it.

[Blake Fernandez:]

Okay, got it. This may be for Barry or Kevin, but the exploration expense was a little bit above what maybe we would have thought considering that Australia is spilling into fourth quarter. Are there any other moving pieces in there besides Cameroon that we should be aware of?

[Barry F.R. Jeffery:]

Well we've got the range we gave you of $100 million, right, from $50 million to $150 million. So that's basically made up of -- we're partnering in the Madagascar well in the Gulf. That's sort of in that 40 -- sorry you're talking about third quarter?

[Blake Fernandez:]

Yes, I'm sorry, Barry, I am talking about third quarter.

[Roger W. Jenkins:]

[indiscernible] on that Blake. I'm disappointed in my team's drilling of that well, and it's supposed to cost about $56 million and it costs $70-something million. So I mentioned in my comments to a previous caller who took a kick on the well, so we didn't do a good job of executing the well. So well is a little more expensive than we thought. And then Barry can give you the spend of the other things [indiscernible] That's the situation in Cameroon. Go ahead, Barry, with the other spend.

[Barry F.R. Jeffery:]

So back to third quarter, Blake, I mean, was there any other specifics you needed there?

[Blake Fernandez:]

No, no, no. That was the main issue I was worried about was 3Q because it -- I think Roger basically covered it. So I think we're squared away there. The final one for you, Roger, this is probably back to you. But just any thoughts on M&A specifically on unconventional. I know now that you've got the team up and running in Eagle Ford, it seems like you guys are delivering there, and you've got a team in place. Any appetite on adding to the portfolio?

[Roger W. Jenkins:]

Well, we are up and running well. We have built that team, it's a significant team and a great accomplishment. There was a previous caller asking about OpEx, and we have low drilling costs. It is going very well. We built that off of our success we had long term in Calgary led by the same person, Mike McFadyen. We do have a group of people looking at M&A, as any company of our market cap would have. And we do have the ability now to execute that would lead you to where we could pay, I suppose. I know we can do the execution. But we're not interested in doing M&A for the sense of just growing or worrying about exploration or anything like that. We need something that has return. If we have something that makes return and fits into something we think we can execute on, we'll look at those. We probably look at that more than people think. But we are interested in working real hard on making return for our shareholders. So looking at it probably harder than we were 2 years ago, and going forward as a normal course of our business today would be the best way to describe it.

[Operator:]

We'll now go to Guy Baber from Simmons & Company International.

[Guy A. Baber:]

Roger, I was just wondering if you had any early thoughts on 2014 capital spending. I believe the prior guidance was $3.6 billion for E&P, which would imply slowdown in spending versus the current run rate. Just trying to get a sense of whether or not that $3.6 billion is still a good number? And where that slowdown might come from in the portfolio?

[Roger W. Jenkins:]

We don't have our budget approved until December. We usually talk about that in the February call. But we do not -- we're not going to have a major surprise in that in my view and there will be a major pullback in spending because we're putting all these shallow water Malaysia projects online, the Siakap North, the Kakap, the 4 projects in Sarawak, and we're doing a lot of the execution at Dalmatian. Eagle Ford would be about the same; exploration, a little bigger probably. But we're in the middle of all that with our budget. But you're not going to be surprised with a blowout of the number that you mentioned.

[Guy A. Baber:]

Okay. Great. And then I apologize, this is a detailed modeling one. But I believe you are scheduled for lifting in Congo during 4Q. And presumably there would be some costs that you will need to book associated with that. So can you provide any guidance on the level of cost there that might accompany that lifting, just order of magnitude? And could we look back to 1Q, the last time, you had a lifting there and use that as a base line? Just any information you could provide there will be helpful. Just don't want to be surprised, 4Q on the cost side.

[Kevin G. Fitzgerald:]

In terms of the lifting, we do have a lifting scheduled in Q4. And because of those low amount of production being produced there, the cost will virtually offset on the production. And the lift itself will virtually offset the value of the oil, assuming there's no major change in oil price. So there's not a lot of P&L impact from that lift at all.

[Operator:]

And we'll now go to Ed Westlake from Crédit Suisse.

[Scott Willis:]

This is Scott Willis on for Ed. I just wanted to quickly focus on the CapEx. It looks like based on your current run rate, you'd be coming in a little below your current guidance. So should we expect that the CapEx is going to be more kind of 4Q weighted to get to that amount? Or do you think it will come in a little lower?

[Roger W. Jenkins:]

I think we're pretty in line with CapEx, maybe slightly lower. And we talked about various shortages of CapEx, I guess, will be about $400 million short this year cash flow, CapEx. And when you add on our dividends and if we're able to do some additional repurchase, we feel that, that can be a counterbalance throughout the year by the dividend we receive from Murphy USA and if we're able to close on the Milford Haven. But today we have no pullout of our revolver and all in our long-term debt outside of the Kakap lease. And, Kevin, do you want to provide any additional...

[Kevin G. Fitzgerald:]

I'd have to say that there shouldn't be -- we should be pretty close to the number. There shouldn't be a major amount that flops over into 2014. Of course, if you ended up with some weather delay or something like that, you could always have those sorts of issues. But -- and for our internal numbers, we're still using the same guidance we've given out to you all.

[Scott Willis:]

Okay, great. And just one last one. Would you be able to give me the contribution in the quarter from any of the newly tied-in assets in Malaysia?

[Roger W. Jenkins:]

And which quarter are you talking about, sir?

[Scott Willis:]

In 3Q, if there was any contribution.

[Roger W. Jenkins:]

Very little in the third quarter. We're just putting these assets on. Serendah's only been on since October 29. And the South Acis is already in from the prior quarter. And the others are staged to come on more for the rest of the year.

[Operator:]

[Operator Instructions] We'll now go to Pavel Molchanov from Raymond James.

[Pavel Molchanov:]

I know that exploration expense guidance is always a bit of a black box. But from the low end of $50 million to the high end of $150 million, can you just walk us through the major variables there?

[Kevin G. Fitzgerald:]

We have our expert, Barry Jeffery, to walk you through that.

[Barry F.R. Jeffery:]

Sure, Pavel. I try to get off on the wrong foot there with Blake. So here we go. So we've got a $100 million variance there that we're talking about, where in the Madagascar well and the Gulf of Mexico, our share there is, say, in the $45 million range. Got the Dufresne well in Australia, that's about $30 million. And then we had a Brunei well scheduled to kick off, and that's about $25 million. So there's your $100 million.

[Pavel Molchanov:]

Okay, got it. And then sorry if you mentioned this already. But Cameroon, obviously a disappointment. Is -- does that condemn the rest of the program in that country? Or are you rethinking it? In other way, sort of Suriname worked out in the past, or are you still committed to it?

[Roger W. Jenkins:]

Well we're still very much committed to it. As I said to an earlier caller, we took a kick on the well that proved hydrocarbon migration to that area, which is a great derisk for us. We found nice sand development there, and it has a different trapping feature or different risk to trap. We didn't do well drilling the well. I think we can learn from that, and drill this well cheaper possibly. And no, very glad to drill the well. And it's up and down that coast, the margin Equatorial Guinea that would have nothing to do with that. And Suriname has both the fan feature surrounded by lots of leased acreage and data and also a very big 4-way closure Cretaceous opportunity there. I see nothing from that well that would preclude me from wanting to do any of the rest of my program. It's just another well in the long list of wells we have.

[Pavel Molchanov:]

Okay, planning to drill in Cameroon next year?

[Roger W. Jenkins:]

Planning to. Yes, sir.

[Operator:]

And it appears there are no further questions. However, I would like to give everyone one final opportunity. [Operator Instructions] And it appears there are no further questions, so I will turn the conference back over to our presenters for any additional or closing remarks.

[Barry F.R. Jeffery:]

That's all we have today, and thank everyone for calling in. And we'll see you at our next call. Appreciate it. Thank you.

[Operator:]

This concludes today's presentation. Thank you for your participation.